As the price or shortage of high quality crude oil increases, there will be an ever-increasing demand to find ways to better exploit lower quality feedstocks and extract fuel values therefrom. Lower quality feedstocks may have relatively high quantities of potentially-fouling causing components, such as asphaltenes, coke, and coke pre-cursors, which are difficult to process and commonly cause fouling of conventional catalysts and hydroprocessing equipment. As more economical ways to process lower quality feedstocks become available, such feedstocks may possibly catch, or even surpass, higher quality crude oils, in the not-too-distant future, as the primary source of refined fossil fuels used to operate automobiles, trucks, farm equipment, aircraft, and other vehicles that rely on internal combustion.
Hydrocracking is used in the petroleum industry to process crude oil and/or other petroleum products for commercial use by preventing or inhibiting the fouling by the potentially fouling-causing components. Hydrocracking is a catalytic cracking process using an elevated partial pressure of hydrogen gas to purify the hydrocarbon stream. Ebullated-bed hydrocracking is one type of hydrocracking that may be used for resid conversion, and the ebullated-bed hydrocrackers may have a continuous addition and/or removal of catalysts. However, hydrocracking is subject to asphaltene precipitation as the saturates and aromatics contained in the hydrocarbon fluid that hold the asphaltenes in solution are removed or converted, which is driven by asphaltene-solubility chemistry. Fouling may occur downstream from the ebullated bed hydrocracker reactor, such as in bottom stream areas, atmospheric column bottoms, vacuum-column bottoms, vacuum-column furnaces, high- and mid-pressure separators, and the like. Extensive fouling may result in unplanned shutdowns, downtime and lost production and consequently increased operating costs.
Conversion reaction rates (thermal cracking), leading to fouling by asphaltenes decomposition, increase more rapidly with rising temperatures compared to the hydrogen-saturation reactions that inhibit sediment formation. Accordingly, temperatures and conversions above pre-determined limits may lead to uncontrolled sediments and coke generation. However, operating below the pre-determined limits only results in lost conversion with no major advantages in terms of sediment deposition control and run lengths.
Asphaltenes are most commonly defined as that portion of petroleum, which is soluble in xylene and toluene, but insoluble in heptane or pentane. Asphaltenes exist in crude oil as both soluble species and in the form of colloidal dispersions stabilized by other components in the crude oil. Asphaltenes have higher molecular weights and are the more polar fractions of crude oil, and can precipitate upon pressure, temperature, and compositional changes in crude oil resulting from blending or other mechanical or physicochemical processing. Asphaltene precipitation and deposition can cause problems in subterranean reservoirs, upstream production facilities, mid-stream transportation facilities, refineries, and fuel blending operations. In petroleum production facilities, asphaltene precipitation and deposition can occur in near wellbore reservoir regions, wells, flowlines, separators, and other equipment. Once deposited, asphaltenes present numerous problems for crude oil producers. For example, asphaltene deposits can plug downhole tubulars, wellbores, choke off pipes and interfere with the functioning of safety shut-off valves, and separator equipment. Asphaltenes have caused problems in refinery processes such as desalters, distillation preheat units, and cokers.
In addition to carbon and hydrogen in the composition, asphaltenes may contain nitrogen, oxygen and sulfur species, and may also contain metal species such as nickel, vanadium, and iron. Typical asphaltenes are known to have different solubilities in the formation fluid itself or in certain solvents like carbon disulfide or aromatic solvents, such as benzene, toluene, xylene, and the like. However, the asphaltenes are insoluble in solvents like paraffinic compounds, including but not limited to pentane, heptane, octane, etc. Asphaltene stability can even be disturbed by mixing hydrocarbon-based fluids i.e. such as mixing two types of crude oils together, two types of shale oils together, condensates, and others, of different origins at certain ratios as the chemistry of the hydrocarbon-based fluids from different sources may be incompatible and induce destabilization of the asphaltenes therein. In non-limiting examples, such as during refining or fuel blending, two or more hydrocarbon-based fluids may be mixed together. Sometimes, changes in physical conditions are sufficient to induce destabilization, or even the mixture of different hydrocarbon-based fluids that have incompatible chemistries. Said differently, even if neither hydrocarbon-based fluid, alone, has destabilized foulants or the hydrocarbon-based fluid would not act as a destabilizing additive by itself, the mixing or the mixture of two or more hydrocarbon-based fluids may destabilize the foulants present in either hydrocarbon-based fluid.
Coke is an insoluble organic portion of crude oil, distillation residua, or residua from thermal/catalytic conversion processes, such as including but not limited to visbreaker tar or LC finer/H oil residuum. Coke may have polyaromatic hydrocarbons (PAHs) dispersed therein with a ring structure of about 4 to about 5 or more condensed aromatic rings.
Coke precursors are the fragments that make up the coke. They are often formed by thermal cracking, dealkylation and/or dehydrogenation processes commonly used for the breaking down of complex organic molecules. They are barely soluble in the crude oil and/or residual, but they tend to precipitate. Once they precipitate, the coke precursors tend to polymerize or conglomerate and form coke.
Accordingly, there are large incentives to mitigate fouling during refining. There are large costs associated with shutting down production units because of the fouling components within, as well as the cost to clean the units. The foulants may create an insulating effect within the production unit, reduce the efficiency and/or reactivity, and the like. In either case, reducing the amount of fouling would reduce the cost to produce hydrocarbon fluids and the products derived therefrom.
There is an ongoing need to prevent or inhibit the fouling by the potentially fouling-causing components in a hydrocarbon fluid.